Protective sheath through a casing window

ABSTRACT

Systems, assemblies, and methods are described which relate to drilling a lateral borehole from a primary wellbore. A primary wellbore may have a casing therein. A window may be milled in the casing using a casing bit. The casing bit may pass through the window and into the surrounding formation. A protective sheath coupled to the casing bit may also extend through the window. The casing bit and protective sheath may remain in place while a drill bit slides through the protective sheath. The drill bit may drill through the casing bit and drill the formation to extend the lateral borehole. An anchor may be used to secure the protective sheath and/or casing bit in place. The drill bit may be included in a single trip assembly with the casing bit and protective sheath.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of, and priority to, U.S. PatentApplication Ser. No. 61/832,564 filed on Jun. 7, 2013 and entitled“Protective Sheath Through a Casing Window,” which application isincorporated herein by this reference in its entirety.

BACKGROUND

In exploration and production operations for natural resources such ashydrocarbon-based fluids (e.g., oil and natural gas), a verticalwellbore may be drilled into an earthen formation. If the wellbore comesinto contact with a fluid reservoir, the fluid may then be extracted. Ifthe wellbore doesn't contact the fluid reservoir, or as the resources ina reservoir are depleted, it may be useful to create additionalwellbores to access additional resources. For instance, a new wellboremay be drilled at the site of an additional fluid reservoir.

In some cases, however, directional drilling may be used in lieu ofcreating a new, vertical wellbore. In directional drilling, a lateral ordeviated borehole may be formed and may branch off an existing wellbore.The lateral borehole may extend laterally at a desired trajectorysuitable for reaching a particular site. In creating the lateralborehole, a whipstock may be employed in a method referred to assidetracking.

Whipstocks have a ramped surface providing a travel path for a bitcoupled to a drill string. To create the lateral borehole, the whipstockcan be set at a desired depth and the ramped surface oriented to providea particular drilling trajectory. The whipstock may be located at anopenhole or cased portion of a wellbore. When the wellbore is cased, amilling assembly may be used to mill through, and form a window in, thecasing. Upon forming the window, the milling assembly may be removed anda drilling assembly may be tripped into the wellbore to extend thelateral borehole through the casing window.

SUMMARY OF THE DISCLOSURE

Assemblies, systems and methods of the present disclosure may relate tothe drilling of a lateral borehole from a primary wellbore. In oneexample system, a method includes positioning a drilling assembly withina primary wellbore. The drilling assembly may include a casing bitcoupled to a protective sheath. The casing bit may be used to mill awindow in casing of the primary wellbore, and the protective sheath maybe extended through the window. The drill string and drill bit may beguided through the protective sheath and through the window, and thedrill bit may be used to drill a lateral borehole.

In another example embodiment, a drilling assembly may include a casingbit coupled to a protective sheath. A drill string may also be coupledto, and inside, the protective sheath. The drill string may includedrill bit.

According to another example embodiment, a drilling system may be usedto form a window in a casing of a primary wellbore and to drill alateral borehole off the primary wellbore. The drilling system mayinclude a drillable casing bit configured to mail the window in thecasing. A protective sheath may be coupled to the drillable casing bit.The drilling system may also include an anchor used to anchor theprotective sheath and restrict the protective sheath from movingaxially, rotationally, or both. A drill string may be coupled to aninterior of the protective sheath. The drill string may include a drillbit configured to dill through the drillable casing bit and throughformation around the primary wellbore. A fastener may releasably couplethe drill string to the protective sheath.

This summary is provided solely to introduce some features and conceptsthat are further developed in the detailed description. Other featuresand aspects of the present disclosure will become apparent to thosepersons having ordinary skill in the an through consideration of theensuing description, the accompanying drawings, and the appended claims.This summary is therefore not intended to identify key or essentialfeatures of the claimed subject matter, nor is it intended to be used asan aid in limiting the scope of the claims.

BRIEF DESCRIPTION OF DRAWINGS

In order to describe various features and concepts of the presentdisclosure, a more particular description of certain subject matter willbe rendered by reference to specific embodiments which are illustratedin the appended drawings. Understanding that these drawings depict onlysome example embodiments and are not to be considered to be limiting inscope, nor drawn to scale for all embodiments, various embodiments willbe described and explained with additional specificity and detailthrough the use of the accompanying drawings in which:

FIG. 1 schematically illustrates an example system for drilling alateral borehole, the system including a casing bit for drilling awindow into a casing of a primary wellbore to begin formation of thelateral borehole, in accordance with one embodiment of the presentdisclosure;

FIG. 2 schematically illustrates the system of FIG. 1 followingcommencement of drilling of the lateral borehole using the casing bit,and including extension of the lateral borehole using a drill bitdrilling through the casing bit, in accordance with an embodiment of thepresent disclosure;

FIG. 3 illustrates a partial cross-sectional view of an example systemfor drilling a lateral borehole, the system including a casing bit fordrilling a window in a wellbore casing, a drill string coupled to thecasing bit, and an interior drill bit, in accordance with one embodimentof the present disclosure;

FIG. 4 illustrates a partial cross-sectional view of the system of FIG.3, the casing bit and a portion of the drill string having passedthrough a window of the wellbore casing, in accordance with oneembodiment of the present disclosure;

FIG. 5 schematically illustrates an example window formed in thewellbore casing of FIG. 4;

FIG. 6 illustrates a partial cross-sectional view of the system of FIGS.3 and 4, the casing bit and drilling assembly being anchored to theearthen formation, in accordance with one embodiment of the presentdisclosure;

FIG. 7 illustrates a partial cross-sectional view of the system of FIGS.3, 4 and 6, the interior drill bit having been detached and extendedthrough the protective sheath towards the casing bit, in accordance withan embodiment of the present disclosure;

FIG. 8 illustrates a partial cross-sectional view of the system of FIG.7, with the interior drill bit extending the lateral borehole followingdrilling through the casing bit, in accordance with another embodimentof the present disclosure; and

FIG. 9 illustrates a partial cross-sectional view of another examplesystem for drilling a lateral borehole, the system including an interiordrill bit adjacent the casing bit, and including a deflection assemblycoupled to the casing bit, in accordance with another embodiment of thepresent disclosure.

DETAILED DESCRIPTION

In accordance with some aspects of the present disclosure, embodimentsherein relate to systems and assemblies for drilling a lateral borehole.More particularly, embodiments disclosed herein may relate to drillingsystems, assemblies and methods for drilling a lateral borehole off acased, primary wellbore. Example drilling systems and assemblies mayinclude a casing bit and a drill bit. The casing bit may be coupled to adrill string element which may be coupled to, or may include, aprotective sheath. Upon milling a window in a casing of the cased,primary wellbore, the protective sheath can pass through the window. Thedrill bit may also pass through the window. As the drill bit passesthrough the window, the protective sheath may restrict and potentiallyprevent the drill bit from contacting the casing or a surroundingformation until the drill bit drills through or is otherwise removedfrom the casing bit.

Referring now to FIGS. 1 and 2, schematic diagrams are provided of anexample drilling system 100 that may utilize systems, assemblies andmethods in accordance with one or more embodiments of the presentdisclosure. FIG. 1 shows an example primary wellbore 102 which is, inthis embodiment, a cased wellbore. The cased wellbore shown in FIG. 1includes a casing 104 which may extend along all or a portion of thelength of the primary wellbore 102. The casing 104 may be used for anynumber of reasons. For instance, the casing 104 may be production casingthat is cemented or otherwise secured in place to isolate the primarywellbore 102 from the surrounding formation 106, and/or to providestructural support along the length of the primary wellbore 102. Inother embodiments, the casing 104 may include additional or othercasing, including intermediate casing, surface casing, conductor casing,liner, or other component.

In the particular embodiment illustrated in FIG. 1, the drilling system100 may be provided and may include components to allow drilling of alateral borehole (e.g., lateral borehole 110 of FIG. 2) which branchesoff the primary wellbore 102. The lateral borehole may be drilled usinga drill string 112 to rotate one or more drill bits. In the particularexample embodiment of FIG. 1, the drill string 112 may be coupled to aprotective sheath 126, which in turn may be coupled to a casing bit 116.The casing bit 116 may a mill or otherwise configured to mill into thecasing 104, and to form a window or opening therein. During formation ofthe window, the casing bit 116 may drill partially into the formation106 to initiate a lateral borehole. In some embodiments, the casing bit116 may also be used after full formation of the window to continuedrilling the lateral borehole.

More particularly, some embodiments of the present disclosurecontemplate use of a drill string 112 that can transmit torque and axialloads, and which can transfer such forces to the protective sheath 126.The protective sheath 126 may ultimately transfer such forces to thecasing bit 116. The drill string 112 may therefore include any number ofstructures to facilitate such use for the formation and/or extension ofa lateral borehole. For instance, the drill string 112 may include atubular member. As an example, the tubular member of the drill string112 may include coiled tubing with a downhole motor, jointed/segmentedtubing, a liner, casings (e.g., as part of a casing-while-drillingsystem), or other components, or some combination thereof, to be capableof carrying transmitted loads to the protective sheath 126 andultimately to the casing bit 116. Of course, the drill string 112 mayinclude or be coupled to any number of different components orstructures. In some embodiments, the drill string 112 may include, or becoupled to, multiple sections of jointed pipe, a motor, stabilizers, orother components. An example motor may include a positive displacementmotor (e.g., a mud motor or progressive cavity motor), a turbine orturbodrill motor, an electrical motor, some other type of motor, or acombination of the foregoing. The drill string 112 may also includedirectional drilling and/or measurement equipment. As an example, thedrill string 112 may include a steerable drilling assembly to controlthe direction of drilling of the lateral borehole within the formation106. A steerable drilling assembly may include various types ofdirectional control systems, including rotary steerable systems referredto as push-the-bit or point-the-bit systems, or any other type of rotarysteerable or directional control system. In some embodiments, componentscoupled to the drill string 112 may be part of a bottomhole assembly fordrilling the lateral borehole into the formation 106.

To further facilitate drilling of the lateral borehole, the drillingsystem 100 may include, or be used with, a deflection member 118. Thedeflection member 118 may include a whipstock or any other structurethat may be used to facilitate formation of the window in the casing 102or the lateral borehole. In this particular embodiment, the deflectionmember 118 may include an inclined surface. The inclined surface may begenerally planar, although in other embodiments the inclined surface maybe concave (e.g., to accommodate a rounded casing bit 116, drill string112, etc.), have multiple tiers of differing inclines, or be otherwiseconfigured.

In operation, the drill string 112 and casing bit 116 may be trippedinto the wellbore until they engage with the deflection member 118. Theinclined surface of the deflection member 118 may direct the casing bit116 towards the interior surface of the casing 104. In some embodiments,the deflection member 118 may be anchored or otherwise maintained at adesired position, depth, and orientation in order to deflect the casingbit 116 at a desired location and azimuthal orientation. When at thedesired location and azimuthal orientation, the casing bit 116 may milla window for drilling of a lateral borehole.

A set of one or more anchors 120, packers, or other components may beused to anchor the deflection member 118 at an axial position andazimuthal orientation within the primary wellbore 102. The one or moreanchors 120 and/or other components may define a setting assembly forengaging the sidewalls of the casing 104 in the primary wellbore 102. Inone embodiment, the anchors 120 may be expandable. For instance,hydraulic fluid may be used to expand the anchors 120 from a retractedposition to the expanded position shown in FIG. 1. In other embodiments,however, the anchors 120 that can be set in other manners. For instance,the anchors 120 may expand or be set mechanically, using spring-loadedcomponents, through directed explosive charges, or in other manners.Regardless of the particular manner in which the anchors 120 operate,the anchors 120 optionally have a sufficient ratio of the expandeddiameter relative to the retracted diameter, thereby facilitatingengagement with a sidewall of a casing 104 or primary wellbore 102, topotentially allow use in wellbores having any number of different sizes.In other embodiments, the anchors 120 may be modified, or eveneliminated and replaced by other suitable components usable to securethe deflection member 118 in place.

The drilling system 100 may also include still other or additionalcomponents. By way of example, and as discussed in greater detailherein, the casing bit 116 may be used primarily for milling through thecasing 104. Upon milling through the casing 104, and potentially througha portion of the formation 106, the casing bit 116 may stop rotatingand/or stop advancing. As shown in FIG. 2, a drill bit 122 may then beused to extend the lateral borehole 110.

More particularly, the drill bit 122 of FIG. 2 may be coupled to thedrill string 112 of FIG. 1. The drill string 112 may be used to rotateand advance the protective sheath 126 and the casing bit 116 to form thewindow in the casing 104. In FIG. 1, however, the drill string 112 anddrill bit 122 may be coupled to an interior of the protective sheath 126using a fastener. The fastener may secure the drill string 112 and/ordrill bit 122 relative to the protective sheath 126, and allow axial androtational loads to be transmitted between the drill string 112 and theprotective sheath 126. Upon release of the fastener, however, therotational and axial forces on the drill bit 122 and drill string 112may allow movement independent of the protective sheath 126.Consequently, the drill string 112 and drill bit 122 may be movedthrough the protective sheath 126 and can potentially drill through thecasing bit 116. For purposes of this disclosure, a casing bit 116 whichmay be drilled through by a drill bit 122 may be referred to as a“drillable casing bit”. After drilling through the casing bit 116, whichmay be a drillable casing bit, the drill bit 122 can move into andpotentially extend the lateral borehole 110.

The particular structure, components, and method of use of the drillingsystem 100 may be varied in any number of manners. For instance, thelength of the protective sheath 126 may be varied. Optionally, thelength and size of the protective sheath 126 may be sized based onparticular conditions within the primary wellbore 102 or based oncomponents of the drilling system 100. For instance, as discussedherein, the protective sheath 126 may be coupled to the drill string 112during a milling operation for forming a window in the casing 104.Thereafter, however, the drill string 112 may be detached from theprotective sheath 126 to allow a lateral borehole 110 to be formed orextended. According to at least some embodiments, including theembodiment shown in FIG. 2, the length of the protective sheath 126 mayallow the protective sheath 126 to extend at least from a top of thedeflection member 118 to a position beyond the window milled in thecasing 104. As a result, when the drill bit 122 passes through theinterior of the protective sheath 126, the protective sheath 126 mayrestrict the drill bit 122 from contacting the deflection member 118and/or the casing 104.

If a protective sheath 126 extends from a top of the deflection member118 and fully through the window in the casing 104, the particularlength of the protective sheath 126 may vary depending on a variety offactors. Example factors may include the length of an inclined surfaceof the deflection member 118, a diameter of the primary wellbore 102, adiameter of the casing bit 116, and the like. In other embodiments, thelength of the protective sheath 126 may be selected to give a toleranceto positioning of the protective sheath 126. In such an embodiment, thelength may be extended to allow the protective sheath 126 to start a fewfeet above the top of the deflection member 118 and extend fully to aposition a few feet beyond the milled window in the casing 104. In anysuch embodiments, and for illustration only, an example protectivesheath 126 may have a length of between 5 ft. (1.5 m) and 100 ft. (30.5m). In another embodiment, the length of the protective sheath 126 maybe between 15 ft. (4.6 m) and 60 ft. (18.3 m). In still anotherembodiment, the length of the protective sheath 126 may be between 20ft. (6.1 m) and 40 ft. (12.2 m). For instance, the protective sheath 126may be 30 ft. (9.1 m) in some embodiments. Of course, in otherembodiments, the length of the protective sheath 126 may be greater than100 ft. (305 m) or less than 5 ft. (1.5 m.). Further, the length may ofcourse also be varied if the location of the protective sheath 126 isvaried. For instance, if the protective sheath 126 extends through thewindow in the casing 104, but doesn't extend fully to the top of thedeflection member 118, the protective sheath 126 may be shortened.

When the protective sheath 126 extends from the top of the deflectionmember 118 fully through the casing 104, and optionally an addeddistance in either or both directions, the protective sheath 126 mayhouse the drill bit 122 and protect the drill bit 122 from damage thatcould otherwise result from the drill bit 122 contacting either thedeflection member 118 or the casing 104. Moreover, protecting the drillbit 122 in this manner may further allow a different bit (i.e., drillbit 122) to drill the lateral borehole 110 than the bit (i.e., casingbit 116) used to mill the window in the casing 104. The drill bit 122may not exhibit the wear caused to the casing bit 116 by the casingand/or may be designed for cutting into the formation 106. Such factors,along with reduced damage to the drill bit 122 due to protectionprovided by the protective sheath 126, may increase the drillingefficiency and life of the drill bit 122.

Protection of the drill bit 122 from damage caused by the casing 104and/or deflection member 118 are only some of the features of theprotective sheath 126. In other embodiments, for instance, the drillingsystem 100 may include motors, stabilizers, or other components (e.g.,as part of a bottomhole assembly). These additional components may alsobe protected against damage. Further, particularly for the casing 104,the window may have jagged or uneven edges and the protective sheath 126may protect against interference with the edges of the window. Furtherstill, upon removal of the drill bit 122 and drill string 112 from theprimary wellbore 112, the lateral borehole 110 may be re-entered forperforming additional operations. The protective sheath 126 may be leftin place (and potentially anchored in place). As a result, componentsused to perform the additional operations may be tripped into thewellbore 102 and into the lateral borehole 110 while being guided by theprotective sheath 126. For instance, completion components (e.g.,packers) may be run into the lateral borehole 110, and may pass throughthe protective sheath 126 which protects the components from damage orinterference.

Turning now to FIGS. 3-8, various partial, cross-sectional views areprovided to illustrate another example embodiment of a drilling system200 in accordance with another aspect of the present disclosure. Inparticular, FIGS. 3-8 illustrate various stages of drilling a lateralborehole 210 off of a primary wellbore 202, while also providing aprotective sheath 226 for protecting and guiding a drill bit 222 used toform or extend the lateral borehole 210.

More particularly, FIGS. 3-8 illustrate a primary wellbore 202 formed ina formation 206. The primary wellbore 202 may be formed in any suitablemanner. In this particular embodiment, for instance, the primarywellbore 202 is shown as a cased wellbore and has a casing 204 therein.The casing 204 may generally be a tubular structure adjacent theinterior, peripheral walls of the primary wellbore 202. In someembodiments, the casing 204 may be cemented or otherwise secured inplace within the primary wellbore 202.

Under some circumstances, a lateral, deviated, or branched borehole(e.g., lateral borehole 210 in FIGS. 4 and 6-8) may be drilled. Thelateral bore hole 210 may extend within the formation 206 and at anangle from the primary wellbore 202. For instance, the primary wellbore202 may be oriented generally vertically, and the lateral borehole 210can be formed to extend therefrom at a particular trajectory. Of course,it should be appreciated by a person having ordinary skill in the art inview of the disclosure herein that the primary wellbore 202 may also notbe vertical, and that the degree of deviation of the lateral borehole210 from the primary wellbore 202 can be varied in a number of manners.Indeed, the angles of the primary wellbore 202 and lateral borehole 210may extend at any possible angle relative to each other and/or thesurface. Thus, while a lateral borehole 210 may be formed to extend in agenerally horizontal direction, that direction may or may not be aboutperpendicular relative to the primary wellbore 202 or parallel relativeto a surface of the formation 206. In other embodiments, othertrajectories are obtained, and the lateral borehole 210 may curve alongits path to obtain the desired end trajectory or desired target.

In order to drill and extend the lateral borehole 210, a deflectionmember 218 may be tripped into the primary wellbore 202. FIGS. 3-8somewhat schematically illustrate a side view of the example deflectionmember 218, which in this embodiment is shown as a whipstock. Generallyspeaking, the deflection member 218 may include, or be coupled to,anchors 220 that may be used to set the deflection member 218 at adesired position and orientation. When tripping the deflection member218 into the primary wellbore 202, the anchors 220 may be in a retractedstate (not shown). With the anchors 220 retracted, the deflection member218 may move axially and/or rotationally within the primary wellbore202.

Once the deflection member 218 reaches a desired depth, the deflectionmember may be oriented and secured in place in the primary wellbore 202using the anchors 220. In some embodiments, the anchors 220 are part ofa setting assembly and may expand to engage against the interior wall ofthe casing 204. Such engagement may create a frictional or interferencefit to secure the deflection member 218 in place by resisting axialand/or rotational movement within the primary wellbore 202. The anchors220 may be expandable in any number of manners. For instance, in someembodiments the anchors 220 may by hydraulically actuated. In otherembodiments the anchors 220 may be mechanically or otherwise expandedand/or retracted. Additionally, while the anchors 220 are shown asengaging the casing 204, the anchors 220 optionally may be aligned withan uncased, or openhole, portion of the wellbore 202. In such anembodiment, the anchors 220 may expand to engage the formation 206directly, and potentially may cut into, or pierce, the formation 206 tosecure the deflection member 218 in place.

The deflection member 218 may be used to direct the path of a drillingassembly used to drill a lateral borehole off the primary wellbore 202.In one embodiment, such as where the deflection member 218 is awhipstock, the deflection member 218 may include a ramped surface 228.When anchoring the deflection member 218 in place, the ramped surface228 may be positioned at a desired orientation configured to guide thedrilling assembly along a particular trajectory. As shown in FIG. 3, dueto the ramped surface 228, a width of the deflection member 218 mayincrease from an upper end towards a lower end. As a result, as adrilling assembly that includes the drill string 212, protective sheath226, and casing bit 216 is moved downward into the primary wellbore 202,the ramped surface 228 can urge the drilling assembly radiallyoutwardly, away from a central axis of the primary wellbore 202, andagainst the casing 204, and ultimately into the formation 206. As shownin FIG. 4, for instance, the casing bit 216 can generally follow theincline of the ramped surface 228 and engage the casing 204. Uponcontacting the casing 204, the casing bit 216 can mill an openingtherein. The opening, which is referred to herein as a “window” 230, maybe gradually formed as the casing bit 216 moves along the ramped surface228 and through the casing 204. As a result, the window 230 may have agenerally elongated shape. FIG. 5, for instance, illustrates a side viewof the exterior of the casing 204 with the window 230 formed therein.

As shown in FIG. 5, when the window 230 is formed, the window 230 maynot have a perfectly smooth periphery, but instead may include one ormore jagged or uneven edges. As discussed herein, a drill bit, mill, orother cutting element may pass through the window 230 to form a lateralborehole 210. If unprotected, the drill bit, mill, or other cuttingelement may catch on the jagged edges of the window 230, or otherwisecontact the edges of the window 230. The edges of the window 230 couldalso interfere with other components of a drilling assembly (e.g., drillstring, motor, stabilizer, etc.), or with completion or other componentswhich re-enter the lateral borehole after removal of a drill string.Such engagement or interference can potentially damage the components,make entry into the lateral borehole 210 difficult, or reduce theeffectiveness and/or useful life of a downhole system or bottomholeassembly.

Furthermore, the properties of the casing 204 may significantly differfrom that of the surrounding formation 206. For instance, the casing 204may be formed of a metal (e.g., steel), while the formation 206 may beformed of one or more types of rock or other materials. In some cases, acutting element or bit structure suited for cutting the formation 206may not be as efficient at milling the window 230, or may be more easilydamaged by the casing 204. Embodiments herein, including the drillingsystem 200 of FIGS. 3-8, relate to an example embodiment that may beused to effectively mill a window in a casing 204, while also protectinga cutting element or bit that may be used to form or extend a lateralborehole 210.

More particularly, and returning now to FIGS. 3 and 4, the drillingsystem 200 may include two or more bits, each of which may have multiplecutting structures or elements. In this particular embodiment, thedrilling system 200 includes a casing bit 216 as a first bit, and adrill bit 222 as a second bit. The casing bit 216 may be primarilyconfigured for use in milling a window 230 in the casing 204, while thedrill bit 222 may be primarily configured for use in cutting, shearing,impacting, or otherwise extending the lateral borehole 210 in theformation 206.

In this particular embodiment, the casing bit 216 is shown as beingcoupled to a protective sheath 226 which may in turn be coupled to, andoptionally suspended from, a drill string 212. The drill string 212 mayinclude jointed pipe, casing-while-drilling (“CWD”), or other types ofdrill string elements, or any combination thereof. Torque and axialthrust may be applied to the drill string 212 and transferred to theprotective sheath 226, which may in turn transfer such torque and motionto the casing bit 216.

The drill string 212 may optionally be used to convey drilling mud oranother fluid. Such fluids may, for instance, pass through an interiorof the drill string 212. The fluid may be used in connection with ahydraulic motor or drive system (not shown) to rotate the drill string212, or a component thereof, as well as the protective sheath 226 andthe casing bit 216. In some embodiments, the drilling mud or other fluidmay enter the protective sheath 226, and the casing bit 216 may includeone or more openings therein to allow fluid to pass therethrough. Such afluid may then also act as a coolant on an exterior of the casing bit216 and/or a jet nozzle to flush cuttings away from the face of thecasing bit 216. The drilling fluid may facilitate cutting of the casing204 and/or formation 206, reduce wear of the casing bit 216, and prolongthe life or effectiveness of the casing bit 216.

As discussed herein, the protective sheath 226 and casing bit 216 may belowered toward the deflection member 218 by using the drill string 212.The ramped surface 228 of the deflection member 218 may push the casingbit 216 into the casing 204 where the window 230 may be formed byrotation of the casing bit 216 as weight-on-bit is applied thereto. FIG.3 illustrates the casing bit 216 prior to formation of the window 230,while FIG. 4 illustrates the casing bit 216 after milling of the window230. Also shown in FIG. 4 is the start of a lateral borehole 210branching from the primary wellbore 202.

While the casing bit 216 may be primarily used to mill the window 230 inthe casing 204, the casing bit 216 may also cut, to at least someextent, into the formation 206. Indeed, in some embodiments, the casingbit 216 may partially cut into the formation 206 before the window 230is at its full size. In at least some embodiments, the cutting of theformation 206 may stop at about the same time as completion of thewindow 230. In other embodiments such as that shown in FIG. 4, thecasing bit 216 may continue to cut into the formation 206 even after thewindow 230 is fully formed. In such an embodiment, the amount ofadditional cutting performed using the casing bit 216 may vary. Forinstance, the length of the lateral borehole 210 may vary from a fewinches or centimeters to many feet or meters by the time an operatorceases using the casing bit 216 to drill a portion of the lateralborehole 210.

When the drilling of the formation 206 using the casing bit 216 isstopped, the casing bit 216 may be removed. In other embodiments,however, the casing bit 216 may potentially be left within the lateralborehole 210. As an example, the illustrated embodiment depicts anadditional anchor 232 coupled to the protective sheath 226. When theanchor 232 is in a retracted state as shown in FIGS. 3 and 4, theprotective sheath 226 and the casing bit 216 may advance within thelateral borehole 210. In contrast, by expanding or activating the anchor232, the anchor 232 may engage or grip the formation 206 and restrict,if not prevent, axial and/or rotational movement of the protectivesheath 226 and/or casing bit 216. FIG. 6 illustrates an exampleembodiment in which the anchor 232 has been expanded to engage theformation 206 and restrict movement of the casing bit 216 and protectivesheath 226. The particular manner in which the anchor 232 operates mayvary. For instance, hydraulic fluid may be used to hydraulically expandthe anchor 232. In another embodiment, the anchors 232 may bemechanically, explosively, or otherwise activated.

Optionally, a controller (e.g., a programmable or electronic controller)may be used to facilitate activation. For instance, if an operator ofthe drilling system 200 determines that the window 230 has beencompleted and the length of the lateral borehole 210 is sufficient toallow the anchor 232 to engage the formation 206, a control signal maybe provided in a wireless, physical, conductive, or other manner, orusing some combination of the foregoing. The control signal may open avalve which can allow hydraulic fluid passing within the protectivesheath 226 to then expand the anchor 232. Alternatively, a controlsignal may activate a motor to mechanically expand the anchor 232,release a spring-loaded element, ignite a directed explosive charge, orotherwise expand the anchor 232. Moreover, while the anchor 232 may becontrolled by an operator, in other embodiments the control may beautomatic. For instance, a controller of the anchor 232 may beprogrammed to activate at a particular location, and one or more sensors(e.g., measurement-while-drilling tools, logging-while-drilling tools,smart drill collars, etc.) may provide positioning information to thecontroller to sense when the conditions for activating the anchor 232are present.

When the casing bit 216 is secured in place within the lateral borehole210, a second bit, which is illustrated as a drill bit 222 in FIG. 6,may then be used to extend the lateral borehole 210. In FIG. 6, forinstance, the drill bit 222 is also coupled to the drill string 212.More particularly, the drill bit 222 may be coupled to a distal endportion of the drill string 212, and optionally be located inside theprotective sheath 226 that is also coupled to the drill string 212. Theillustrated drilling system 200 may be intended for use as a single tripdrilling assembly, so that milling of the window 230 and drilling of thelateral borehole 210 may occur in a single trip. In some embodiments,the deflection member 218 and anchor 220 may also be set in a singletrip so that setting of the anchor, milling of the window 230, anddrilling of the lateral borehole 210 may occur in a single trip.

In at least some embodiments, the drill bit 222 or drill string 212 maybe fixed at a particular location within the protective sheath 226 in amanner that allows the drill bit 222 to advance within the primarywellbore 202 and/or lateral borehole 210 at about the same rate as theprotective sheath 226. In this particular embodiment, for instance, afastener 234 may selectively couple the drill string 212 at a particularaxial location within the protective sheath 226. Of course, in otherembodiments, the fastener 234 may directly couple the drill bit 222 tothe protective sheath 226.

Regardless of how or where located, the fastener 234 may provide aconnection that allows rotational and axial forces on the drill string212 to be transferred to the protective sheath 226. Indeed, as describedherein, while fixed to the protective sheath 226, the drill string 212or drill bit 222 may have a rotation that is about synchronous with therotation of the casing bit 216 and/or protective sheath 226. In theillustrated embodiment, for instance, the fastener 234 may effectivelylock the drill bit 222 to the drill string 212. When locked, thefastener 234 may allow rotational movement (i.e., torque) and axialthrust (i.e., weight-on-bit) on the drill string 212 to be transmittedto the protective sheath 226. Thus, the protective sheath 226 and drillstring 212 may have about the same rotation and axial movement. When theanchor 232 is activated to restrict rotation of the drill string 212and/or the casing bit 216, the rotation of both the casing bit 216 anddrill bit 222 may stop. In other embodiments, however, the drill bit 222may rotate independently of the protective sheath 226 and/or casing bit216. For instance, the fastener 234 may be coupled to the drill string212. A motor or other element of a bottomhole assembly associated withthe drill bit 222 may allow the drill bit 222 to rotate at a rate thatis faster or slower relative to rotation of the drill string 212,protective sheath 226, or casing bit 216.

At about the time the casing bit 216 is anchored in place, or sometimethereafter, the drill string 212 may be allowed to rotate and moveaxially relative to the protective sheath 226 and the casing bit 216.Such independent rotation and axial movement may occur using any numberof mechanisms. For instance, the fastener 234 may be deactivated orselectively released. As an example, the fastener 234 may include ahydraulically activated release. Depending on the design of the release,when hydraulic pressure is supplied or cut-off, the fastener 234 mayrelease, allowing the drill bit 222 and drill string 212 to moveindependently of the protective sheath 226. In another embodiment, aball, dart, or other obstruction element may be inserted into the drillstring 212 and may land on a seat. Pressure may build behind the seatand obstruction element to break one or more shear pins of the fastener234. In other embodiments, a spring-loaded release, or other mechanicalsystem may be activated to detach the drill string 212 and/or drill bit222 relative to the protective sheath 226. Any such deactivation orrelease may be controlled by an operator, or may be automatic. Forinstance, mud-pulse telemetry, pressure pulses, rotational speedsignals, wired drill pipe connections, wireless signals, active orpassive RFID tags, or other mechanisms may be used to convey a signalfrom an operator on the surface to a downhole controller. In anotherembodiment, a controller may include a sensor that measures rotation ofthe protective sheath 226. When the rotation stops or drops below aparticular threshold, the fastener 234 may deactivate to release thedrill string 212 or the drill bit 222.

In another embodiment, the fastener 234 may include a sacrificialelement. For a drive system using a motor, drilling mud or another fluidmay be used to rotate the drill string 212 and/or the drill bit 222.Optionally, the drilling mud or other fluid can be supplied to a motorassociated with the drill bit 222 anchoring the protective sheath 234;however, such rotation may also occur while the casing bit 216 is in useand un-anchored. If the rotations of the drill bit 222 and the casingbit 216 are synchronous (or the rotations of the corresponding drillstring 212 and protective sheath 226), the sacrificial element of thefastener 234 may also rotate synchronously and remain in place.Restricting rotation of the protective sheath 226, however, may not stopthe drill bit 222 or drill string 212 from rotating. Instead, a driveforce may continue to be applied to the drill string 212 and/or drillbit 222. The drive force may apply a torque that ultimately causes thesacrificial element to break and fail, thereby releasing the drillstring 212 and drill bit 222 from the protective sheath 226. The drillstring 212 and drill bit 222 may then be able to rotate and move axiallywithin the interior of the drill string 212.

The fastener 234 may be located at any suitable location, and the drillbit 222 may therefore be fastened at any suitable location along thelength of the protective sheath 226. In the embodiment illustrated inFIG. 6, the drill bit 222 is shown as being fixed at location that is inan upper end portion of the protective sheath 226. In some embodiments,upon anchoring of the protective sheath 226, the drill bit 222 may stillbe located within the primary wellbore 202. Such an embodiment is,however, merely illustrative. In other embodiments (e.g., the embodimentshown in FIG. 9), the drill bit 222 may be anchored at a location moreproximate the casing bit 216, such that as the casing bit 216 isanchored in place, the drill bit 222 may already be located at leastpartially within the lateral borehole 210.

Regardless of the distance at which the drill bit 222 is positionedrelative to the casing bit 216, when the fastener 234 is released andthe drill bit 222 can move axially along the protective sheath 226, thedrill bit 222 may pass through the window 230 prior to drilling orextending a length of the lateral borehole 210. As discussed herein, thewindow 230 may be surrounded by edges of the casing 204 that canpotentially damage the drill bit 222, whether on account of the materialof the casing 204, the shape of the edges around the window 230, orother factors. In accordance with some embodiments of the presentdisclosure, the protective sheath 226 may shield the drill bit 222 andthe drill string 212 from contacting the edges of the window 230 orpotentially any part of the casing 204 or deflection member 218.

More particularly, as discussed herein, the protective sheath 226 may beanchored in place and may extend from the interior of the primarywellbore 202, through the window 230, and into the lateral borehole 210.The protective sheath 226 may, at its outer surface, potentially contactthe deflection member 218 and/or casing 204. The drill bit 222 and drillstring 212, however, may be located within the protective sheath 226.Thus, as the drill bit 222 moves from a location within the primarywellbore 202 (FIG. 6) through the window 230 and to the lateral borehole210 (FIG. 7), the drill bit 222 may be shielded from direct contact withthe deflection member 218 and/or the edges of the window 230.

The protective sheath 226 may be formed in any number of differentmanners. For instance, as discussed herein, the protective sheath 226may include a tubular member coupled to (e.g., suspended from) a portionof the drill string 212. Optionally, the protective sheath 226 may havethe same or different properties relative the drill string 212, casing204, or other components of the drilling system 200. In someembodiments, the protective sheath 226 may be configured to bend orflex, may be jointed, or otherwise structured. The protective sheath 226may also be part of a bottomhole assembly, or a separate componentcoupled to a bottomhole assembly associated with the drill bit 222. Anexample protective sheath 226 may include CWD components to allow theprotective sheath 226 to form a casing extending through the window 230and into the lateral borehole 210. In such an embodiment, the anchor 232may cement or otherwise fix a casing within the lateral borehole 210. Inat least some embodiments, the protective sheath 226 may include a jointto facilitate bending and assist in forming a channel to guide the drillbit 222 into the lateral borehole 210. In some embodiments, theprotective sheath 226 may include expandable casing.

The protective sheath 226 may provide other uses other than protectingthe drill bit 222 as the drill bit 222 moves through the window 230. Asdiscussed herein, a deflection member 218 may be used to orient thedrill string 212 at a desired trajectory. The drill string 212 may alsorestrict the drill bit 222 and drill string 214 from contacting thedeflection member 218. The protective sheath 226 may, however, generallydefine the path from the primary wellbore 202 to the lateral borehole210, and can thus act as a guide to the drill bit 222. In particular,the drill bit 222 and drill string 212 may be sized to allow the drillbit 222 to move within the protective sheath 226, which may act as aslide through which the drill bit 222 may move towards the casing bit216 and ultimately to the distal end of the lateral borehole 210 asshown in FIG. 7. When anchored, the protective sheath 226 may alsoremain in place during not only lateral drilling of the lateral borehole210 using the drill bit 222, but also potentially during re-entry ofother components, including completion or other intervention components.

When the drill bit 222 reaches the end of the protective sheath 226, thecasing bit 216 may obstruct further movement of the drill bit 222. Insome embodiments, however, the casing bit 216 and drill bit 222 may becoordinated to allow the drill bit 222 to drill through the casing bit216. For instance, the casing bit 216 may be a drillable casing bitand/or have an optional opening therein. When the opening is included,the opening may be used to center the drill bit 222 and/or to allow thedrill bit 222 to more efficiently begin drilling through the casing bit216. In some embodiments, the opening may have a size and/or lengthconfigured to allow the casing bit 216 to effectively mill the window230 and start the lateral borehole 210, while also minimizing orreducing the amount of material through which the drill bit 222 maydrill through to reach the exterior of the casing bit 216. In at leastsome embodiments, the interior of the casing bit 216 may be formed of amaterial that is different than at least some materials on an exteriorof the casing bit 216. As an example, superhard or superabrasivematerials (e.g., polycrystalline diamond, tungsten carbide, metalborides, etc.), or cutters having such materials, may be located on theexterior of the casing bit 216, while the interior of the casing bit 216may have a different, and relatively softer, material (e.g., steel,iron, etc.). The drill bit 222 may be formed in any suitable manner forcutting through the interior of the casing bit 216 as well as throughrock or other materials of the formation 206. In some embodiments, theinterior of the casing bit 216 may be configured to allow the drill bit222 to drill through the casing bit 216 at least nearly as efficientlyas through the formation 206.

When the drill bit 222 has drilled through the casing bit 216, the drillbit 222 may then be at the distal end of the lateral borehole 210. Insuch an embodiment, by continuing to drive the drill bit 222 by applyingweight-on-bit (e.g., using axial loading on the drill string 212), thelateral borehole 210 may be extended. As shown in FIG. 8, for instance,the drill bit 222 may be used to form an extended length 211 of thelateral borehole 210. In some embodiments, such as where the drill bit222 is smaller than the casing bit 216, the extended length 211 of thelateral borehole 210 may also have a reduced size (e.g., width ordiameter).

The above description of certain embodiments, including the embodimentsillustrated in FIGS. 3-8, contains certain specific elements that areintended to be illustrative only, and may be varied in any number ofmanners. For instance, while the drilling system 200 described hereinhas been described as enabling a single trip operation, such anembodiment is merely illustrative. In other embodiments, for instance, adrilling system 200 may include a protective sheath 226 and a casing bit216 to mill a window in a casing 204, but may not include a drill bit222. Instead, an entirely separate assembly may be tripped into theprimary wellbore 202 and guided by the protective sheath 226 to extend alateral borehole 210.

Further, a deflection member 218 as described herein may have any numberof other constructions. For instance, a ramped surface 228, or a portionthereof, may have an incline between 0.5° and 15° relative to alongitudinal axis of the primary wellbore 202. More particularly, theramped surface 228 may have an incline with lower and upper limits thatinclude any of 0.5°, 1°, 1.5°, 2°, 2.5°, 3°, 3.5°, 4°, 5°, 7.5°, 10°,12.5°, 15°, or any value therebetween. For instance, at least a portionof the ramped surface 228 may be inclined at an angle of between 2° and5° relative to the longitudinal axis of the primary wellbore 202. Instill another embodiment, the ramped surface may be inclined at 3°. Instill other embodiments, the ramped surface 228, or a portion thereof,may have an angle of less than 0.5°, or greater than 15°, relative tothe longitudinal axis of the primary wellbore 202. In some embodiments,the angle of the ramped surface 228 may be an average angle of inclineover multiple different stages having different inclines.

The deflection member 218 may be tripped into the primary wellbore 202separate from the drill string 212. In other embodiments, however, thedrill string 212 and deflection member 218 may be part of the samedrilling assembly to allow for single trip setting of the deflectionmember 218, milling of the window 230, drilling of the lateral borehole210, or some combination thereof.

FIG. 9, for instance, illustrates an example embodiment of a drillingsystem 300 that may be used for single trip drilling of a lateralborehole. In the drilling system 300 of FIG. 9, the drilling system 300may also be used to anchor a deflection member 318 and mill a window ina casing 304 in the same, single trip.

Many of the components of the drilling system 300 may be similar invarious regards to components described in embodiments describedelsewhere herein, or illustrated in FIGS. 1-8. Accordingly, to avoidunnecessarily obscuring aspects of the disclosure, certain details willnot be repeated relative to the drilling system 300, but should insteadbe understood to be equally applicable to the embodiment shown in FIG.9. Indeed, each embodiment disclosed herein is intended to includecomponents and features that may be interchanged with features andcomponents of other embodiments disclosed herein.

In the embodiment shown in FIG. 9, the drilling system 300 may be usedto form a lateral borehole off of a primary wellbore 302 that includes acasing 304 therein. The drilling system 300 may itself include adeflection member 318, a casing bit 316, and a drill bit 322 coupledtogether using a drill string 312, protective sheath 326, fasteners 334,connectors 336, or other components that allow single trip installationand/or use.

The deflection member 318 may include a whipstock or any othercomponents suitable for deflecting the casing bit 316 against the casing304 for formation of a window. In this embodiment, the deflection member318 includes a setting assembly having one or more expandable anchors320. The expandable anchors 320 are illustrated in a retracted state inwhich a width of the anchors 320 may be less than the interior diameterof the casing 304, thereby allowing the deflection member 318 to beinserted into, or retracted from, the primary wellbore 302.

The deflection member 318 is further illustrated as including aconnector 336. In general, the connector 336 may couple the deflectionmember 318 to the casing bit 316. The connector 336 may have sufficientstructural strength and integrity to maintain the deflection member 318coupled to the casing bit 316 when tripped into the primary wellbore302, but may be structured to break or release at a desired time orlocation. For instance, when the anchors 320 are expanded, the casingbit 316 may begin to rotate. When the deflection member 318 is fixed atan axial and/or rotational position, the rotation of the casing bit 316may generate a torque or other force causing the connector 336 to fail.When the connector 336 fails, the deflection member 318 may becomedetached from the casing bit 316. It will be appreciated by a personhaving ordinary skill in the art, however, that the connector 336 may beused to decouple the deflection member 318 from the casing bit 316 ordrill string 312 in any number of manners, and need not be or include asacrificial element. Indeed, in some embodiments, the connector 336 maybe selectively couplable to allow decoupling from, and re-couplingbetween, the deflection member 318 and the casing bit 316.

Upon separation of the deflection member 318 from the casing bit 316,the drill string 312 may be used to advance the casing bit 316 withinthe primary wellbore 302. Advancing the casing bit 316 may cause thecasing bit 316 to move toward, and mill a window into, the casing 304.As discussed herein, when the casing bit 316 has milled a window, andoptionally cut at last a portion of the formation 306 to start a lateralborehole, use of the casing bit 316 may be discontinued. The casing bit316 may also be secured at an axial and/or rotational position in usingan anchor 332 or other securement device (either directly or, as shownin FIG. 9, by coupling the anchor 332 to the protective sheath 326).Thereafter, the drill bit 322 may be advanced within the protectivesheath 326 towards the casing bit 316. The drill bit 322 may drillthrough the casing bit 316 and then into the formation 306 to extend thelateral borehole.

The protective sheath 326 may protect the drill bit 322 and/or the drillstring 312 against contact with the casing 304 (e.g., at the edges ofthe window in the casing 304); however, the protective sheath 326 mayalso provide other uses. For instance, the protective sheath 326 mayprotect other components of the drilling system 300. For instance, abottomhole assembly including the drill bit 322 may include a stabilizer333 or other components (e.g., mud motor, drill collars, sensors, jars,tractors, conveyors, vibration tools, etc.). The stabilizer 333 andother components may also pass through the protective sheath 326 to beprotected from contact with the casing 304 or the deflection member 318.In other embodiments, completion or other components may enter theprimary wellbore 302 following removal of the drill string 312, and canpass through the protective sheath 326 to be protected against damagefrom the deflection member 318 and/or the casing 304.

As discussed herein, the drill string 312 may be coupled to a protectivesheath 326. The protective sheath 326 may provide a slide or guide forthe drill bit 322 to allow the drill bit 322 to move through a window inthe casing 304 without directly contacting the casing 304. In anotherembodiment, the protective sheath 326 may be separable from the drillstring 312 (e.g., using fasteners 334). In one example embodiment, theprotective sheath 326 may include components of a CWD system.Optionally, a joint 313 may couple components of the protective sheath326 to each other. The joint 313 may be a CWD joint, and can be used tocouple CWD or other component of the protective sheath 326, tofacilitate bending or flexure of the protective sheath 326, or for anynumber of other purposes.

The drill bit 322 may be directly or indirectly coupled to the drillstring 312, protective sheath 326, or casing bit 316 so as to be part ofthe same drilling assembly, and to allow single trip drilling of thelateral borehole. The fastener 334, which is shown as coupling the drillstring 312 to the protective sheath 326, may be used to make such aconnection. Optionally, the fastener 334 may include a sacrificialelement, hydraulic release, or other type of connector to allowselective decoupling of the drill bit 322 from the protective sheath326.

The particular location of the fastener 334 and/or location of aconnection of the drill bit 322 can be varied. Relative to theembodiment in FIGS. 3-8, for instance, the drill bit 322 is shown asbeing fastened in a distal end portion near the casing bit 316. In oneembodiment, the drill bit 322 may be generally aligned in a longitudinaldirection with the anchor 332, or potentially nearer the casing bit 316than the anchor 332. In such an embodiment, as the casing bit 316 millsa window in the casing 304, and is anchored to the formation 306, theprotective sheath 326 may guide and protect the drill bit 322 throughthe window even before the fastener 334 is selectively released todecouple the drill bit 322 or drill string 312 from the protectivesheath 326. When decoupled, the drill bit 322 may be used toindependently drill within the lateral borehole, and can potentiallydrill through the casing bit 316 and/or into the formation 306 to formor extend the lateral borehole. In some embodiments, the drill bit 332may be a fixed cutter, roller cone, impregnated diamond, or otherdrilling bit. In some embodiments, the drill bit 332 may have a fixedouter or gauge diameter. In other embodiments, the drill bit 332 may bean expandable drill bit. Similarly, the casing bit 316 may have a fixeddiameter or may be expandable.

In the description herein, various relational terms are provided tofacilitate an understanding of various aspects of some embodiments ofthe present disclosure. Relational terms such as “bottom,” “below,”“top,” “above,” “back,” “front,” “left,” “right,” “rear,” “forward,”“up,” “down,” “horizontal,” “vertical,” “clockwise,” “counterclockwise,”“upper,” “lower,” “uphole,” “downhole,” and the like, may be used todescribe various components, including their operation and/orillustrated position relative to one or more other components.Relational terms do not indicate a particular orientation for eachembodiment within the scope of the description or claims. For example, acomponent of a bottomhole assembly that is described as “below” anothercomponent may be further from the surface while within a verticalwellbore, but may have a different orientation during assembly, whenremoved from the wellbore, or in a deviated borehole. Accordingly,relational descriptions are intended solely for convenience infacilitating reference to various components, but such relationalaspects may be reversed, flipped, rotated, moved in space, placed in adiagonal orientation or position, placed horizontally or vertically, orsimilarly modified. Certain descriptions or designations of componentsas “first,” “second,” “third,” and the like may also be used todifferentiate between identical components or between components whichare similar in use, structure, or operation. Such language is notintended to limit a component to a singular designation. As such, acomponent referenced in the specification as the “first” component maybe the same or different than a component that is referenced in theclaims as a “first” component.

Furthermore, while the description or claims may refer to “anadditional” or “other” element, feature, aspect, component, or the like,it does not preclude there being a single element, or more than one, ofthe additional element. Where the claims or description refer to “a” or“an” element, such reference is not be construed that there is just oneof that element, but is instead to be inclusive of other components andunderstood as “at least one” of the element. It is to be understood thatwhere the specification states that a component, feature, structure,function, or characteristic “may,” “might,” “can,” or “could” beincluded, that particular component, feature, structure, orcharacteristic is provided in some embodiments, but is optional forother embodiments of the present disclosure. The terms “couple,”“coupled,” “connect,” “connection,” “connected,” “in connection with,”and “connecting” refer to “in direct connection with,” or “in connectionwith via one or more intermediate elements or members.” Components thatare “integral” or “integrally” formed include components made from thesame piece of material, or sets of materials, such as by being commonlymolded or cast from the same material, or commonly machined from thesame piece of material stock. Components that are “integral” should alsobe understood to be “coupled” together.

Although various example embodiments have been described in detailherein, those skilled in the art will readily appreciate in view of thepresent disclosure that many modifications are possible in the exampleembodiments without materially departing from the present disclosure.Accordingly, any such modifications are intended to be included in thescope of this disclosure. Likewise, while the disclosure herein containsmany specifics, these specifics should not be construed as limiting thescope of the disclosure or of any of the appended claims, but merely asproviding information pertinent to one or more specific embodiments thatmay fall within the scope of the disclosure and the appended claims. Thevarious embodiments discussed herein may be used in combination, andvarious features disclosed in one embodiment are intended to be usablein connection with other embodiments disclosed herein.

A person having ordinary skill in the art should realize in view of thepresent disclosure that equivalent constructions do not depart from thespirit and scope of the present disclosure, and that various changes,substitutions, and alterations may be made to embodiments disclosedherein without departing from the spirit and scope of the presentdisclosure. Equivalent constructions, including functional“means-plus-function” clauses are intended to cover the structuresdescribed herein as performing the recited function, including bothstructural equivalents that operate in the same manner, and equivalentstructures that provide the same function. It is the express intentionof the applicant not to invoke means-plus-function or other functionalclaiming for any claim except for those in which the words ‘means for’appear together with an associated function. Each addition, deletion,and modification to the embodiments that falls within the meaning andscope of the claims is to be embraced by the claims.

While embodiments disclosed herein may be used in oil, gas, or otherhydrocarbon exploration or production environments, such environmentsare merely illustrative. Systems, tools, assemblies, methods, millingsystems, and other components of the present disclosure, or which wouldbe appreciated in view of the disclosure herein, may be used in otherapplications and environments. In other embodiments, milling tools,deflection elements, methods of milling and drilling, or otherembodiments discussed herein, or which would be appreciated in view ofthe disclosure herein, may be used outside of a downhole environment,including in connection with other systems, including within automotive,aquatic, aerospace, hydroelectric, manufacturing, other industries, oreven in other downhole environments. The terms “well,” “wellbore,”“borehole,” and the like are therefore also not intended to limitembodiments of the present disclosure to a particular industry. Awellbore or borehole may, for instance, be used for oil and gasproduction and exploration, water production and exploration, mining,utility line placement, or myriad other applications.

Certain embodiments and features may have been described using a set ofnumerical values that may provide lower and upper limits. It should beappreciated that ranges including the combination of any two values arecontemplated unless otherwise indicated, and that a particular value maybe defined by a range having the same lower and upper limit. Allnumbers, percentages, ratios, measurements, or other values statedherein are intended to include not only the stated value, but also othervalues that are about or approximately the stated value, as would beappreciated by one of ordinary skill in the art encompassed byembodiments of the present disclosure. A stated value should thereforebe interpreted broadly enough to encompass values that are at leastclose enough to the stated value to perform a desired function orachieve a desired result. The stated values include at leastexperimental error and variations that would be expected by a personhaving ordinary skill in the art, as well as the variation to beexpected in a suitable manufacturing or production process. A value thatis about or approximately the stated value and is therefore encompassedby the stated value may further include values that are within 5%,within 1%, within 0.1%, or within 0.01% of a stated value.

The Abstract at the end of this disclosure is provided to allow thereader to quickly ascertain the general nature of some embodiments ofthe present disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

What is claimed is:
 1. A method for drilling a lateral borehole from acased, primary wellbore, comprising: positioning a drilling assemblywithin a primary wellbore, the drilling assembly including a casing bitcoupled to a protective sheath; milling a window in a casing of theprimary wellbore with the casing bit; extending the protective sheaththrough the window; guiding a drill string and drill bit through theprotective sheath and through the window; and drilling a lateralborehole using the drill bit.
 2. The method recited in claim 1, thecasing bit being a drillable casing bit, wherein drilling the lateralborehole including: drilling through the casing bit using the drill bit.3. The method recited in claim 1, further comprising: anchoring theprotective sheath following extending the protective sheath through thewindow.
 4. The method recited in claim 3, wherein anchoring theprotective sheath includes anchoring the protective sheath to restrictat least one of axial or rotational movement of the protective sheath.5. The method recited in claim 1, wherein the protective sheath is acasing while drilling joint coupled to the drill string.
 6. The methodrecited in claim 1, wherein milling the window in the casing furtherincludes using the casing bit to initiate drilling of the lateralborehole.
 7. The method recited in claim 1, wherein the drill string iscoupled to an interior of the protective sheath.
 8. The method recitedin claim 7, wherein drilling the lateral borehole includes releasing thedrill string from the protective sheath.
 9. The method recited in claim1, further comprising: anchoring a deflection member within the primarywellbore; and deflecting the casing bit into the casing using thedeflection member.
 10. The method recited in claim 1, wherein extendingthe protective sheath includes positioning the protective sheathpartially through the window.
 11. A drilling assembly, comprising: acasing bit; a protective sheath coupled to the casing bit; and a drillstring coupled to an interior of the protective sheath, the drill stringincluding a drill bit.
 12. The drilling assembly recited in claim 11,further comprising: an anchor coupled to the protective sheath.
 13. Thedrilling assembly recited in claim 11, the casing bit being a drillablecasing bit and configured to mill through casing of a wellbore.
 14. Thedrilling assembly recited in claim 11, further comprising: a fastenerselectively coupling the drill string to the protective sheath.
 15. Thedrilling assembly recited in claim 14, the fastener including asacrificial element.
 16. The drilling assembly recited in claim 11,further comprising: a deflection member releasably coupled to the casingbit.
 17. The drilling assembly recited in claim 16, further comprising:an anchor coupled to the deflection member.
 18. A drilling system forforming a window in a casing of a primary wellbore and drilling alateral borehole off the primary wellbore, comprising: a drillablecasing bit configured to mill a window in casing of a primary wellbore;a protective sheath coupled to the drillable casing bit; an anchorconfigured to anchor the protective sheath and restricting at least oneof axial or rotational motion of the protective sheath; a drill stringcoupled to, and within the protective sheath, the drill string includinga drill bit configured to drill through the drillable casing bit andthrough formation around the primary wellbore; and a fastener releasablycoupling the drill string to the protective sheath.
 19. The drillingsystem recited in claim 18, the anchor being selectively expandable toanchor the protective sheath within the formation.
 20. The drillingsystem recited in claim 18, further comprising: a deflection memberreleasably coupled to at least one of the drillable casing bit or theprotective sheath.